Revisions to Electric Rate Schedules E-19 and E-20 in Compliance
with Decision 14-12-080

Purpose
Pacific Gas and Electric Company (PG&E) hereby modifies its Electric Rate Schedules
E-19 and E-20 in compliance with Decision (D.) 14-12-080.
The filing would not increase any current rate or charge, cause the withdrawal of service
or conflict with any rate schedule or rule, except as discussed below.
Background
On December 18, 2014, the California Public Utilities Commission (Commission or
CPUC) approved D.14-12-080, Decision on a Rate Design Proposal to Adopt an Option
R Tariff for Pacific Gas and Electric Company.
D.14-12-080 directs PG&E to offer to Schedule E-19 and E-20 customers a new rate
option termed “Option R.” Option R will be available on a voluntary basis to qualifying
E-19 and E-20 customers that have installed solar photovoltaic (PV or solar). To qualify
for Option R, a customer’s annual solar output must be at least 15 percent of the
customer’s annual energy usage. Per D.14-12-080, Option R is not available to
customers with other non-solar types of distributed generation. Option R converts 100
percent of peak and part-peak generation demand charges, and 75 percent of peak and
part-peak distribution demand charges, to peak and part-peak energy charges. Solar
customers on Schedule E-19V, for voluntary Schedule E-19 service below 500 kW, are
also eligible for Option R.
Ordering Paragraph (OP) 1 of the Decision orders that “Within 45 days of the issuance
of this decision, Pacific Gas and Electric Company shall file a Tier 2 Advice Letter with
revised tariff sheets for rate schedules E-19 and E-20 that include an Option R.” The
Decision was issued on December 19, 2014, so this Advice Letter is timely filed. Also

Advice 4581-E

-2-

February 2, 2015

per OP 1, the Option R rates will be effective June 1, 2015, unless PG&E’s pending
Application For Rehearing of D.14-12-080 is granted before that date.
Proposed Revisions
This Advice Letter proposes the following changes to Electric Rate Schedule E-19,
consistent with the Decision:
• Addition of rate tables showing total and unbundled Option R rates.
• Addition of Section 20, which explains Option R terms and conditions and
proposes the calculation to determine that a PV system is providing 15 percent or
more of annual electricity usage.
This Advice Letter proposes the following changes to Electric Rate Schedule E-20,
consistent with the Decision:
• Addition of rate tables showing total and unbundled Option R rates.
• Addition of Section 18, which explains Option R terms and conditions and
proposes the calculation to determine that a PV system is providing 15 percent or
more of annual electricity usage.
Revenue Neutrality
OP 1 to D.14-12-080 provides as follows:
“The Option R rates shall shift all revenues collected for generation
capacity costs from peak and part-peak demand charges to peak and
part-peak energy charges in a manner that would be revenue neutral
within the E-19 and E-20 customer classes. The Option R rates shall shift
75% of the revenues collected for distribution capacity costs from peak
and part-peak demand charges to peak and part-peak energy charges.
The tariff sheets shall become effective June 1, 2015, subject to Energy
Division determining that they are in compliance with this order.”
The Option R rates presented in the attached tariff sheets present Option R rates
consistent with OP 1. The Option R rates shown in the attached tariff sheets have not
been adjusted in any way to account for revenue shortfalls. PG&E proposes that future
adjustments for the treatment of revenue shortfalls attributable to Option R be
incorporated into future Schedule E-19 and E-20 rates as described below.
The Option R rates presented in the attached tariff sheets are based on revenue
neutrality with respect to the rates for Schedules E-19 and E-20 that are currently
effective. Because further rate changes are expected before Option R rates are
implemented on June 1, the attached rates are illustrative and may need to be updated
to be consistent with the rates for Schedules E-19 and E-20 that will be effective as of
the June 1, 2015 implementation date.

Advice 4581-E

-3-

February 2, 2015

Revenue Shortfalls
To comply with the directive in OP 1 that Option R rates be revenue neutral within the
class, and consistent with the language in D.14-12-080, that, “As a result of this
decision, some revenues will likely be shifted among customers on the E-19 and E-20
tariffs,”1 PG&E proposes an ex post, or after-the-fact, methodology for calculating the
revenue shortfall from offering Option R and ensuring that it remains within the E-19 and
E-20 customers classes. This ex post methodology is consistent with similar practices
approved by the CPUC where revenue shortfalls could not be accurately forecast, but
were none-the-less required to be retained within the originating class.2,3
PG&E proposes to allocate all Option R revenue shortfalls back to the rate schedule
and voltage of origin.
Tariff Revisions
In Attachment 1, PG&E presents the tariff revisions necessary to incorporate solar
Option R into Schedules E-19 and E-20.

Protests
Anyone wishing to protest this filing may do so by letter sent via U.S. mail, facsimile or
E-mail, no later than February 23, 2015, which is 21 days4 after the date of this filing,
due to the fact that the 20th day falls on a Sunday. Protests must be submitted to:
CPUC Energy Division
ED Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, California 94102
Facsimile: (415) 703-2200
E-mail: EDTariffUnit@cpuc.ca.gov
Copies of protests also should be mailed to the attention of the Director, Energy
Division, Room 4004, at the address shown above.
The protest shall also be sent to PG&E either via E-mail or U.S. mail (and by facsimile,
if possible) at the address shown below on the same date it is mailed or delivered to the
Commission:
Meredith Allen
Senior Director, Regulatory Relations
Pacific Gas and Electric Company
77 Beale Street, Mail Code B10C
P.O. Box 770000
San Francisco, California 94177
Facsimile: (415) 973-7226
E-mail: PGETariffs@pge.com
Any person (including individuals, groups, or organizations) may protest or respond to
an advice letter (General Order 96-B, Section 7.4). The protest shall contain the
following information: specification of the advice letter protested; grounds for the protest;
supporting factual information or legal argument; name, telephone number, postal
address, and (where appropriate) e-mail address of the protestant; and statement that
the protest was sent to the utility no later than the day on which the protest was
submitted to the reviewing Industry Division (General Order 96-B, Section 3.11).

4

The 20-day protest period concludes on a weekend. PG&E is hereby moving this date to the
following business day.

Advice 4581-E

-5-

February 2, 2015

Effective Date
As ordered by OP 1 of D.14-12-080, PG&E requests that this Tier 2 advice filing
become effective on June 1, 2015, subject to Energy Division determining that PG&E is
in compliance with this order. On January 20, 2015, PG&E filed an Application for
Rehearing of D.14-12-080 in A.12-12-002. If PG&E’s Application for Rehearing is
approved, PG&E will withdraw this advice letter.
Notice
In accordance with General Order 96-B, Section IV, a copy of this advice letter is being
sent electronically and via U.S. mail to parties shown on the attached list and the parties
on the service list for A.12-12-002. Address changes to the General Order 96-B service
list should be directed to PG&E at email address PGETariffs@pge.com. For changes to
any other service list, please contact the Commission’s Process Office at (415) 7032021 or at Process_Office@cpuc.ca.gov.
Send all electronic approvals to
PGETariffs@pge.com. Advice letter filings can also be accessed electronically at:
http://www.pge.com/tariffs/.

Advice Letter (AL) #: 4581-E
Tier: 2
Subject of AL: Revisions to Electric Rate Schedules E-19 and E-20 in Compliance with Decision 14-12-080
Keywords (choose from CPUC listing): Compliance
AL filing type:  Monthly  Quarterly  Annual  One-Time  Other _____________________________
If AL filed in compliance with a Commission order, indicate relevant Decision/Resolution #: D.14-12-080
Summarize differences between the AL and the prior withdrawn or rejected AL: ____________________
Is AL requesting confidential treatment? If so, what information is the utility seeking confidential treatment for: No
Confidential information will be made available to those who have executed a nondisclosure agreement: N/A
Name(s) and contact information of the person(s) who will provide the nondisclosure agreement and access to the confidential
information: __________________________________________________________________________________________________
Resolution Required? Yes No
Requested effective date: June 1, 2015

No. of tariff sheets: 30

Estimated system annual revenue effect (%): N/A
Estimated system average rate effect (%): N/A
When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small
commercial, large C/I, agricultural, lighting).
Tariff schedules affected: Electric Rate Schedules E-19 and E-20
Service affected and changes proposed: New Option for Electric Rate Schedules E-19 and E-20
Pending advice letters that revise the same tariff sheets: N/A
Protests, dispositions, and all other correspondence regarding this AL are due no later than 21 days1 after the date of this filing, unless
otherwise authorized by the Commission, and shall be sent to:
California Public Utilities Commission
Energy Division
EDTariffUnit
505 Van Ness Ave., 4th Flr.
San Francisco, CA 94102
E-mail: EDTariffUnit@cpuc.ca.gov

Definition of Maximum Demand: Demand will be averaged over 15-minute intervals
for customers whose maximum demand exceeds 499 kW. “Maximum demand” will be
the highest of all the 15-minute averages for the billing month. If the customer’s use of
electricity is intermittent or subject to severe fluctuations, a 5-minute interval may be
used. If the customer has any welding machines, the diversified resistance welder
load, calculated in accordance with Section J of Rule 2, will be considered the
maximum demand if it exceeds the maximum demand that results from averaging the
demand over 15-minute intervals. The customer’s maximum-peak-period demand will
be the highest of all the 15-minute averages for the peak period during the billing
month. (See Section 6 for a definition of “Peak-Period.”) See Section 14 for the
definition of maximum demand for customers voluntarily selecting E-19.
Solar Pilot Program: Customers who exceed 499 kW for at least three consecutive
months during the most recent 12-month period and must otherwise take service on
mandatory Schedule E-19 may elect service under Schedule A-6 under the terms
outlined in the Solar Photovoltaic (solar or PV) Pilot Program section of Schedule A-6.

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Option R for Solar: The Option R rate is available to qualifying E-19 customers,
including voluntary E-19 customers, with PV systems that provide 15% or more of their
annual electricity usage. For additional Option R details and program specifics, see
Sections 3 and 20.

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Standby Demand: For customers for whom Schedule S—Standby Service Special
Conditions 1 through 6 apply, standby demand is the portion of a customer’s maximum
demand in any month caused by nonoperation of the customer’s alternate source of
power, and for which a demand charge is paid under the regular service schedule.
If the customer imposes standby demand in any month, then the regular service
maximum demand charge will be reduced by the applicable reservation capacity
charge (see Schedule S Special Condition 1).
To qualify for the above reduction in the maximum demand charge, the customer must,
within 30 days of the regular meter-read date, demonstrate to the satisfaction of PG&E
the amount of standby demand in any month. This may be done by submitting to
PG&E a completed Electric Standby Service Log Sheet (Form 79-726).
2. TERRITORY:

Total bundled service charges are calculated using the total rates shown below. Direct
Access (DA) and Community Choice Aggregation (CCA) charges shall be calculated in
accordance with the paragraph in this rate schedule titled Billing.

_________________________
*
Transmission, Transmission Rate Adjustments, and Reliability Service charges are combined for
presentation on customer bills.
**
Distribution and New System Generation Charges are combined for presentation on customer bills.

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(Continued)
Advice Letter No:
Decision No.
8D11

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Original

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

Sheet 9

ELECTRIC SCHEDULE E-19
MEDIUM GENERAL DEMAND-METERED TOU SERVICE
3.

35053-E

Rates: (Cont’d.)
UNBUNDLING OF TOTAL RATES FOR OPTION R (Cont’d.)
(for qualifying solar customers as set forth in Section 20)

_________________________
*
Transmission, Transmission Rate Adjustments, and Reliability Service charges are combined for
presentation on customer bills.
**
Distribution and New System Generation Charges are combined for presentation on customer bills.
*** Only customers that qualify as Small Businesses – California Climate Credit under Rule 1 are eligible for
the California Climate Credit.

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TYPES OF CHARGES: The customer’s monthly charge for service under
Schedule E-19 is the sum of a customer charge, demand charges, and energy
charges:
–

The customer charge is a flat monthly fee.

–

This schedule has three demand charges, a maximum-peak-perioddemand charge, a maximum part-peak-period and a maximum-demand
charge. The maximum-peak-period-demand charge per kilowatt applies to
the maximum demand during the month’s peak hours, the maximum partpeak-period demand charge per kilowatt applies to the maximum demand
during the month’s part-peak hours, and the maximum demand charge per
kilowatt applies to the maximum demand at any time during the month. The
bill will include all of these demand charges. (Time periods are defined in
Section 6.)

–

The energy charge is the sum of the energy charges from the peak,
partial-peak, and off-peak periods. The customer pays for energy by the
kilowatt-hour (kWh), and rates are differentiated according to time of day
and time of year.

–

The meters required for this schedule may become obsolete as a result of
electric industry restructuring or other action by the California Public Utilities
Commission. Therefore, any and all risks of paying the required charges
and not receiving commensurate benefit are entirely that of the customer.

–

The monthly charges may be increased or decreased based upon the
power factor. (See Section 7.)

–

As shown on the rate chart, which set of customer, demand, and energy
charges is paid depends on the level of the customers maximum demand
and the voltage at which service is taken. Service voltages are defined in
Section 5 below.

PG&E will install a time-of-use meter that is appropriate for this schedule that measures
and registers the amount of electricity a customer uses.

Customers with a maximum demand of 200 kW or greater for three consecutive months
must have an interval data meter that can be read remotely by PG&E. A Meter Data
Management Agent (MDMA) may also read the customer’s meter on behalf of the
customer’s Energy Service Provider (ESP) if a customer is receiving Direct Access
Service.
For bundled service customers with a maximum demand of 200 kW or greater for
three consecutive months, PG&E will provide and install the interval data meter at no
additional cost to the customer. After the interval meter is installed, the customer must
take service on a time-of-use schedule. The installation of an interval data meter for
customers taking service under the provisions of Direct Access is the responsibility of
the customer’s Energy Service Provider, or their Agent, and must be installed in
accordance with Electric Rule 22.
If the customer does not currently qualify for an interval data meter, the customer must
pay PG&E for the cost of purchasing and installing an interval meter, together with
applicable Income Tax Component of Contribution (ITCC) charges and the cost to
operate and maintain the interval meter, and must sign an Interval Meter Installation
Service Agreement (Form 79-984).
Customers who also request any meter data management services must also sign an
Interval Meter Data Management Service Agreement (Form 79-985) and must have an
appropriate interval data meter.
5. DEFINITION
OF SERVICE
VOLTAGE:

The following defines the three voltage classes of Schedule E-19 rates. Standard
Service Voltages are listed in Rule 2, Section B.1.
a.

Secondary: This is the voltage class if the service voltage is less than 2,400 volts
or if the definitions of “primary” and “transmission” do not apply to the service.

b.

Primary: This is the voltage class if the customer is served from a “single customer
substation” or without transformation from PG&E’s serving distribution system at
one of the standard primary voltages specified in PG&E’s Electric Rule 2, Section
B.1.

c.

Transmission: This is the voltage class if the customer is served without
transformation from PG&E’s serving transmission system at one of the standard
transmission voltages specified in PG&E’s Rule 2, Section B.1.

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(Continued)
Advice Letter No:
Decision No.
11D7

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-19
MEDIUM GENERAL DEMAND-METERED TOU SERVICE
6. DEFINITION
OF TIME
PERIODS:

HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays are
legally observed.
DAYLIGHT SAVING TIME ADJUSTMENT: The time periods shown above will begin and
end one hour later for the period between the second Sunday in March and the first
Sunday in April, and for the period between the last Sunday in October and the first
Sunday in November.
CHANGE FROM SUMMER TO WINTER OR WINTER TO SUMMER: When a billing
month includes both summer and winter days, PG&E will calculate demand charges as
follows. It will consider the applicable maximum demands for the summer and winter
portions of the billing month separately, calculate a demand charge for each, and then
apply the two according to the number of billing days each represents.
7. POWER
FACTOR
ADJUSTMENTS:

Bills will be adjusted based on the power factor for all customers except those selecting
voluntary E-19 service. The power factor is computed from the ratio of lagging reactive
kilovolt-ampere-hours to the kilowatt-hours consumed in the month. Power factors are
rounded to the nearest whole percent.
The rates in this rate schedule are based on a power factor of 85 percent. If the average
power factor is greater than 85 percent, the total monthly bill will be reduced by the product
of the power factor rate and the kilowatt-hour usage for each percentage point above
85 percent. If the average power factor is below 85 percent, the total monthly bill will be
increased by the product of the power factor rate and the kilowatt-hour usage for each
percentage point below 85 percent.

Power factor adjustments will be assigned to distribution for billing purposes.

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(Continued)
Advice Letter No:
Decision No.
12D7

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-19
MEDIUM GENERAL DEMAND-METERED TOU SERVICE

35057-E
26948-E

Sheet 13

8. CHARGES
FOR TRANSFORMER AND
LINE LOSSES:

The demand and energy meter readings used in determining the charges will be
adjusted to correct for transformation and line losses in accordance with Section B.4 of
Rule 2.

9.

If PG&E must install any new or additional facilities to provide the customer with service
under this schedule the customer may have to pay some of the cost. Any advance
necessary and any monthly charge for the facilities will be specified in a line extension
agreement. See Rules 2, 15, and 16 for details. This section does not apply to
customers voluntarily taking service under Schedule E-19.

STANDARD
SERVICE
FACILITIES:

Facilities installed to serve the customer may be removed when service is discontinued.
The customer will then have to repay PG&E for all or some of its investment in the
facilities. Terms and conditions for repayment will be set forth in the line extension
agreement.
10. SPECIAL
FACILITIES:

PG&E will normally install only those standard facilities it deems necessary to provide
service under this schedule. If the customer requests any additional facilities, those
facilities will be treated as “special facilities” in accordance with Section I of Rule 2.

11. ARRANGEMENTS FOR
VISUALDISPLAY
METERING:

If the customer wishes to have visual-display metering equipment in addition to the
regular metering equipment, and the customer would like PG&E to install that
equipment, the customer must submit a written request to PG&E. PG&E will provide
and install the equipment within 180 days of receiving the request. The visual-display
metering equipment will be installed near the present metering equipment. The
customer will be responsible for providing the required space and associated wiring.
PG&E will continue to use the regular metering equipment for billing purposes.

Common-area accounts that are separately metered by PG&E and which took electric
service from PG&E on or prior to January 16, 2003, have a one-time opportunity to
return to a residential rate schedule from April 1, 2004 to May 31, 2004, by notifying
PG&E in writing.
In the event that the CPUC substantially amends any or all of PG&E’s commercial or
residential rate schedules, the Executive Council of Homeowners (ECHO) can direct
PG&E to begin an optional second right-of-return period lasting 105 days. However, if
this occurs prior to the April 1, 2004 to May 31, 2004, time period, the ECHO directed
right of return period will be the only window for returning to a residential schedule.
Newly constructed common-areas that are separately metered by PG&E and which first
took electric service from PG&E after January 16, 2003, have a one-time opportunity to
transfer to a residential rate schedule during a two-month window that begins 14 months
after taking service on a commercial rate schedule. This must be done by notifying
PG&E in writing. These common-area accounts have an additional opportunity to return
to a residential schedule in the event that ECHO directs PG&E to begin a second rightof-return period.
Only those common-area accounts taking service on Schedule E-8 prior to moving to
this tariff may return to Schedule E-8.
Common-area accounts are those accounts that provide electric service to Common
Use Areas as defined in Rule 1.

Customers voluntarily taking service on Schedule E-19 (see Applicability Section) shall
be governed by all the terms and conditions shown in Sections 1 through 12, unless
different terms and conditions are shown below.
a.

DEFINITION OF MAXIMUM DEMAND: Demand will be averaged over
15-minute intervals except, in special cases. “Maximum demand” will be the
highest of all 15-minute averages for the billing month.
SPECIAL CASES: (1) If the customer’s use of energy is intermittent or subject to
severe fluctuations, a 5-minute interval may be used; and (2) If the customer
uses welders, the demand charge will be subject to the minimum demand
charges for those welders' ratings, as explained in Section J of Rule 2.

14. BILLING:

b.

REDUCED CUSTOMER CHARGE: The reduced customer charge will be
assessed only if the customer is taking service under this schedule on a voluntary
basis or if the customer’s maximum billing demand has not exceeded 499 kW for
12 or more consecutive months.

c.

SERVICE CONTRACTS: This rate schedule will remain in effect for at least
twelve consecutive months before another schedule change is made, unless the
customer’s maximum demand has exceeded 499 kW for three consecutive
months.

A customer’s bill is calculated based on the option applicable to the customer.

Facilities which meet the eligibility criteria in Rule 19.2 or 19.3 are eligible for a California
Alternate Rates for Energy discount under Schedule E-CARE. CARE customers are
exempt from paying the DWR Bond Charge rate component. For CARE customers, no
portion of the rates shall be used to pay the DWR bond charge. Generation is calculated
residually based on the total rate less the sum of the following: Transmission,
Transmission Rate Adjustments, Reliability Services, Distribution, Public Purpose
Programs, Nuclear Decommissioning, New System Generation Charges1, Competition
Transition Charges (CTC), and Energy Cost Recovery Amount.

_________________
1
Per Decision 11-12-031, New System Generation Charges are effective 1/1/2012.

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As set forth in CPUC Decision 01-04-006, all transmission level customers except
essential use customers, Optional Binding Mandatory Curtailment (OBMC) plan
participants, net suppliers to the electrical grid, or others exempt by the Commission, are
to be included in rotating outages in the event of an emergency. A transmission level
customer who refuses or fails to drop load shall be added to the next rotating outage
group so that the customer does not escape curtailment. If the transmission level
customer fails to cooperate and drop load at PG&E's request, automatic equipment
controlled by PG&E will be installed at the customer’s expense per Electric Rule 2. A
transmission level customer who refuses to drop load before installation of the
equipment shall be subject to a penalty of $6/kWh for all load requested to be curtailed
that is not curtailed. The $6/kWh penalty shall not apply if the customer’s generation
suffers a verified, forced outage and during times of scheduled maintenance. The
scheduled maintenance must be approved by both the ISO and PG&E, but approval
may not be unreasonably withheld.

SOLAR GENERATION FACILITIES EXEMPTION: Customers who utilize solar
generating facilities which are less than or equal to one megawatt to serve load and who
do not sell power or make more than incidental export of power into PG&E’s power grid
and who have not elected service under Schedule NEM, will be exempt from paying the
otherwise applicable standby reservation charges.
DISTRIBUTED ENERGY RESOURCES EXEMPTION: Any customer under a
time-of-use (TOU) rate schedule using electric generation technology that meets the
criteria as defined in Electric Rule 1 for Distributed Energy Resources is exempt from the
otherwise applicable standby reservation charges. Customers qualifying for this
exemption shall be subject to the following requirements. Customers qualifying for an
exemption from standby charges under Public Utilities (PU) Code Sections 353.1 and
353.3, as described above, must take service on a TOU schedule in order to receive this
exemption until a real-time pricing program, as described in PU Code 353.3, is made
available. Once available, customers qualifying for the standby charge exemption must
participate in the real-time program referred to above. Qualification for and receipt of
this distributed energy resources exemption does not exempt the customer from
metering charges applicable to TOU and real-time pricing, or exempt the customer from
reasonable interconnection charges, non-bypassable charges as required in Preliminary
Statement BB - Competition Transition Charge Responsibility for All Customers and
CTC Procurement, or obligations determined by the Commission to result from
participation in the purchase of power through the California Department of Water
Resources, as provided in PU Code Section 353.7.

18. DWR BOND
CHARGE:

The Department of Water Resources (DWR) Bond Charge was imposed by California
Public Utilities Commission Decision 02-10-063, as modified by Decision 02-12-082, and
is property of DWR for all purposes under California law. The Bond Charge applies to all
retail sales, excluding CARE and Medical Baseline sales. The DWR Bond Charge
(where applicable) is included in customers' total billed amounts.

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(Continued)
Advice Letter No:
Decision No.
18D8

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-19
MEDIUM GENERAL DEMAND-METERED TOU SERVICE

19. PEAK DAY
PRICING
DETAILS:

35063-E
31284-E

Sheet 19

a.

Default Provision: The default of eligible customers to PDP will occur once per
year with the start of their billing cycle on or after November 1. Eligible customers
will have at least 45-days notice prior to their planned default date when they may
opt-out of PDP rates to take service on TOU rates. During the 45-day period,
customers will continue to take service on their non-PDP rate. Customers may
elect any applicable PDP rate. However, if the customers taking service on this
schedule have not made that choice or elected to opt-out to a TOU rate at least five
(5) days before their proposed default date, their service will be defaulted to the
PDP version of this rate schedule on their default date. Existing customers on a
PDP rate eligible demand response program will have the option to enroll.

b.

Capacity Reservation Level: Customers may elect a capacity reservation level
(CRL) and pay for a fixed level of capacity, specified in kW. While the CRL is
applicable year round, customers electing a CRL will be billed on a take-or-pay
basis up to the specified CRL under the non-PDP rate of this schedule during the
summer period (May 1 through October 31). This means that customers will be
billed for summer peak generation demand charges up to the level of their CRL,
even in summer months when the actual demand might be less than their CRL.
Customers will receive PDP credits on summer usage above the CRL on summerperiod non-PDP event days. All usage during a PDP event protected under the
CRL will be billed at the non-PDP rate. All usage above the CRL (as measured in
15-minute intervals), and not protected during a PDP event, will be billed at the
PDP rate.
If a customer fails to elect an initial CRL, the customer’s initial CRL will be set at
50% of its most recent six (6) summer months’ average peak-period maximum
demand and may go back to previous year to make a full summer season (if
available). If the customer has not established any historic summer billing demand,
the CRL will be set at zero (0).
A customer may only elect to change their CRL once every 12 months.

c.

Bill Stabilization: PDP customers will be offered bill stabilization for the initial twelve
(12) months unless they opt-out during their initial 45-day period. Bill stabilization
ensures that during the initial 12 months under PDP, the customer will not pay more
than it would have had it opted-out to the applicable TOU rate.
If a customer terminates its participation on the PDP rate prior to the initial 12
month period expiring, the customer will receive bill stabilization up to the date
when the customer terminates its participation. Bill stabilization benefits will be
computed on a cumulative basis, based on the earlier of 1) when a customer
terminates its participation on the PDP rate or 2) at the end of the initial 12-month
period. Any applicable credits will be applied to the customer’s account on a
subsequent regular bill. Bill stabilization is only available one time per customer. If
a customer un-enrolls or terminates its participation on a PDP rate, bill stabilization
will not be offered again.

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Notification Equipment: Customers, at their expense, must have access to the
Internet and an e-mail address or a phone number to receive notification of a PDP
event. In addition, all customers can have, at their expense, an alphanumeric pager
or cellular telephone that is capable of receiving a text message sent via the
Internet, and/or a facsimile machine to receive notification messages.
If a PDP event occurs, customers will be notified using one or more of the abovementioned systems. Receipt of such notice is the responsibility of the participating
customer. PG&E will make reasonable efforts to notify customers, however it is the
customer’s responsibility to maintain accurate notification contact information,
receive such notice and to check the PG&E website to see if an event is activated.
PG&E does not guarantee the reliability of the phone, text messaging, e-mail
system or Internet site by which the customer receives notification.
PG&E may conduct notification test events once a month to ensure a customer’s
contact information is up-to-date. These are not actual PDP events and no load
reduction is required.

e.

Demand Response Operations Website: Customers with demands of 200 kW or
greater for three consecutive months can use PG&E’s demand response operations
website located at https://inter-act.pge.com for load curtailment event notifications
and communications.
The customer’s actual energy usage is available at PG&E’s demand response
operations website or on “My Account”. This data may not match billing quality
data, and the customer understands and agrees that the data posted to PG&E’s
demand response operations website or on “My Account” may be different from the
actual bill.

f.

Program Operations: A maximum of fifteen (15) PDP events and a minimum of
nine (9) PDP events may be called in any calendar year. PG&E will notify
customers by 2:00 p.m. on a day-ahead basis when a PDP event will occur the next
day. The PDP program will operate year-round and PDP events may be called for
any day of the week. PDP events will be called from 2:00 p.m. to 6:00 p.m.

g.

Event Cancellation: PG&E may initiate the cancellation of a PDP event before 4:00
p.m. the day-ahead of a noticed PDP event. If PG&E cancels an event, it will count
the cancelled event toward the PDP limits.

h.

Event Trigger: PG&E will trigger a PDP event when the day-ahead temperature
forecast trigger is reached. The trigger will be the average of the day-ahead
maximum temperature forecasts for San Jose, Concord, Red Bluff, Sacramento and
Fresno.

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Beginning May 1 of each summer season, the PDP events on non-holiday
weekdays will be triggered at 98 degrees Fahrenheit (°F), and will be triggered at
105°F on holidays and weekends. If needed, PG&E will adjust the non-holiday
weekday trigger up or down over the course of the summer to achieve the range of
9 to 15 PDP events in any calendar year. Such adjustments would be made no
more than once per month and would be posted to the demand response
operations website or on PG&E’s PDP website.
PDP events may also be initiated as warranted on a day-ahead basis by 1) extreme
system conditions such as special alerts issued by the California Independent
System Operator, 2) under conditions of high forecasted California spot market
power prices, 3) to meet annual PDP event limits for a calendar year, or 4) for
testing/evaluation purposes.

i.

Program Terms: A customer may opt-out anytime during their initial 12 months on
a PDP rate. After the initial 12 months, customer’s participation will be in
accordance with Electric Rule 12.
Customers may opt-out of a PDP rate at anytime to enroll in another demand
response program beginning May 1, 2011.

j.

20. Option R

Interaction with Other PG&E Demand Response Programs: Customers on a PDP
rate may participate in a day-of dispatchable demand response program as
established in D.09-08-027.

The Option R rate is available to qualifying E-19 customers, including voluntary E-19
customers, with PV systems that provide 15% or more of their annual electricity usage.
For a customer installing a new PV system, this eligibility requirement will be calculated
as follows:
Annual PV system output1/Annual electricity usage2 ≥ 15%
For a customer with an existing PV system, this eligibility requirement will be calculated
as follows:
3
3
2
Annual PV system output /(Annual PV system output +Annual electricity usage ) ≥ 15%

_________________________
For a customer installing a new system, annual PV system output (kWh) will be
estimated as CEC rating of the panels (kW) * 8,760 hours/year * 18% capacity factor.
2
Annual electricity usage (kWh) will be measured at the PG&E meter over the last 12
months.
3
For a customer with an existing system, the customer may choose to supply PG&E
with reliable metered data measuring annual PV system output, if such data are
available. Alternatively, annual PV system output will be estimated using the formula
in footnote 1.
1

Advice Letter No:
Decision No.
21D10

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

35065-E
29097-E

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February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE
1. APPLICABILITY:
(Cont’d.)

35066-E
30531-E

Sheet 2

Definition of Maximum Demand: Demand will be averaged over 15-minute intervals.
“Maximum demand” will be the highest of all the 15-minute averages for the billing
month. If the customer’s use of electricity is intermittent or subject to severe
fluctuations, a 5-minute interval may be used. If the customer has any welding
machines, the diversified resistance welder load, calculated in accordance with
Section J of Rule 2, will be considered the maximum demand if it exceeds the
maximum demand that results from averaging the demand over 15-minute intervals.
The customer’s maximum-peak-period demand will be the highest of all the 15-minute
averages for the peak period during the billing month. (See Section 6 for a definition of
“Peak-Period.”)
Standby Demand: For customers for whom Schedule S—Standby Service Special
Conditions 1 through 6 apply, standby demand is the portion of a customer’s maximum
demand in any month caused by nonoperation of the customer’s alternate source of
power, and for which a demand charge is paid under the regular service schedule.
If the customer imposes standby demand in any month, then the regular service
maximum demand charge will be reduced by the applicable reservation capacity
charge (see Schedule S Special Condition 1).
To qualify for the above reduction in the maximum demand charge, the customer must,
within 30 days of the regular meter read date, demonstrate to the satisfaction of PG&E
the amount of standby demand in any month. This may be done by submitting to
PG&E a completed Electric Standby Service Long Sheet (Form 79-726).
Solar or Fuel Cell Generation Demand Adjustment: A customer who installs a solar
electric generation facility on or after January 1, 2007, or fuel cell electric generation
facility may be eligible to receive a Generation Demand Adjustment. A customer will
qualify for a Generation Demand Adjustment if both of the following conditions are met:
(1) either the customer’s solar electric generating facility was installed after January 1,
2007, or the customer’s fuel cell electric generation facility was installed (and approved
for interconnection by PG&E); and (2) the electric generation facility reduces the
customer’s maximum demand to the point that the customer would no longer be
eligible for service under this schedule. The Generation Demand Adjustment will be
the fixed reduction in demand as determined by PG&E from the customer’s
interconnection agreement, and will be added to the customer’s maximum demand for
the sole purpose of determining the customer’s eligibility for Schedule E-20.
The Generation Demand Adjustment does not specifically guarantee the customer’s
continued eligibility for service under this schedule nor will it be applied to the
customer’s maximum demand for purposes of calculating the monthly maximum
demand charge.
The Generation Demand Adjustment for solar generating facilities will terminate on
December 31, 2016.
Option R for Solar: The Option R rate is available to qualifying E-20 customers, with
solar photovoltaic (PV) systems that provide 15% or more of their annual electricity
usage. For additional Option R details and program specifics, see Sections 3 and 18.

2. TERRITORY:

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Schedule E-20 applies everywhere PG&E provides electric service.

(Continued)
Advice Letter No:
Decision No.
2D5

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Original

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

Cancelling

Sheet 5

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE
3.

________________________
* Transmission, Transmission Rate Adjustments, and Reliability Service charges are combined for presentation on customer bills.
** Distribution and New System Generation Charges are combined for presentation on customer bills.

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(Continued)
Advice Letter No:
Decision No.
6D8

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE
3.

RATES:
(Cont’d.)

a.

35069-E
31049-E

Sheet 7

TYPES OF CHARGES: The customer’s monthly charge for service under
Schedule E-20 is the sum of a customer charge, demand charges, and energy
charges:
The customer charge is a flat monthly fee.
–

Schedule E-20 has three demand charges, a maximum-peak-perioddemand charge, a maximum-part-peak-period demand charge, and a
maximum-demand charge. The maximum-peak-period-demand charge per
kilowatt applies to the maximum demand during the month’s peak hours, the
maximum-part-peak-demand charge per kilowatt applies to the maximum
demand during the month’s part-peak hours, and the maximum-demand
charge per kilowatt applies to the maximum demand at any time during the
month. The bill will include all of these demand charges. (Time periods are
defined in Section 6.)

–

The energy charge is the sum of the energy charges from the peak, partialpeak, and off-peak periods. The customer pays for energy by the kilowatthour (kWh), and rates are differentiated according to time of day and time of
year.

–

The monthly charges may be increased or decreased based upon the power
factor. (See Section 7.)

–

As shown on the rate chart, which set of customer, demand, and energy
charges is paid depends on the voltage at which service is taken. Service
voltages are defined in Section 5 below.

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(Continued)
Advice Letter No:
Decision No.
7D9

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE

4.

METERING
REQUIREMENTS:

35070-E
24895-E

Sheet 8

An interval data meter that measures and registers the amount of electricity a customer
uses and can be read remotely by PG&E is required for all customers on this schedule.
A Meter Data Management Agent (MDMA) may also read the customer’s meter on
behalf of the customer’s Energy Service Provider (ESP) if a customer is receiving Direct
Access Service.
For bundled service customers with a maximum demand of 200 kW or greater for
three consecutive months, PG&E will provide and install the interval data meter at no
cost to the customer. The installation of an interval data meter for customers taking
service under the provisions of Direct Access is the responsibility of the customer’s
Energy Service Provider, or their Agent, and must be installed in accordance with
Electric Rule 22.
Customers who also request any meter data management services, must also sign an
Interval Meter Data Management Service Agreement (Form 79-985) and must have an
appropriate interval data meter.

5.

DEFINITION
OF SERVICE
VOLTAGE:

The following defines the three voltage classes of Schedule E-20 rates. Standard
Service Voltages are listed in Rule 2.
a.

Secondary: This is the voltage class if the service voltage is less than 2,400 volts
or if the definitions of “primary” and “transmission” do not apply to the service.

b.

Primary: This is the voltage class if the customer is served from a “single customer
substation” or without transformation from PG&E’s serving distribution system at
one of the standard primary voltages specified in PG&E’s Electric Rule 2,
Section B.1.

c.

Transmission: This is the voltage class if the customer is served without
transformation at one of the standard transmission voltages specified in PG&E’s
Electric Rule 2, Section B.1.

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(Continued)
Advice Letter No:
Decision No.
8D9

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE
6.

HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
DAYLIGHT SAVING TIME ADJUSTMENT: The time periods shown above will begin
and end one hour later for the period between the second Sunday in March and the first
Sunday in April, and for the period between the last Sunday in October and the first
Sunday in November.
CHANGE FROM SUMMER TO WINTER OR WINTER TO SUMMER: When a billing
month includes both summer and winter days, PG&E will calculate demand charges as
follows. It will consider the applicable maximum demands for the summer and winter
portions of the billing month separately, calculate a demand charge for each, and then
apply the two according to the number of billing days each represents.
7.

POWER
FACTOR
ADJUSTMENTS:

The bill will be adjusted based upon the power factor. The power factor is computed
from the ratio of lagging reactive kilovolt-ampere-hours to the kilowatt-hours consumed
in the month. Power factors are rounded to the nearest whole percent.
The rates in this rate schedule are based on a power factor of 85 percent. If the average
power factor is greater than 85 percent, the total monthly bill will be reduced by the
product of the power factor rate and the kilowatt-hour usage for each percentage point
above 85 percent. If the average power factor is below 85 percent, the total monthly bill
will be increased by the product of the power factor rate and the kilowatt-hour usage for
each percentage point below 85 percent.
Power factor adjustments will be assigned to distribution for billing purposes.

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(Continued)
Advice Letter No:
Decision No.
9D9

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE

35072-E
22787-E

Sheet 10

8.

CHARGES
FOR
TRANSFOR
MER AND
LINE
LOSSES:

The demand and energy meter readings used in determining the charges will be
adjusted to correct for transformation and line losses in accordance with Section B.4 of
Rule 2.

9.

STANDARD
SERVICE
FACILITIES:

If PG&E must install any new or additional facilities to provide the customer with service
under Schedule E-20, the customer may have to pay some of the cost. Any advance
necessary and any monthly charge for the facilities will be specified in a line extension
agreement. See Rules 2, 15, and 16 for details.
Facilities installed to serve the customer may be removed when service is discontinued.
The customer will then have to repay PG&E for all or some of its investment in the
facilities. Terms and conditions for repayment will be set forth in the line extension
agreement.

10. SPECIAL
FACILITIES:

PG&E will normally install only those standard facilities it deems necessary to provide
service under Schedule E-20. If the customer requests any additional facilities, those
facilities will be treated as “special facilities” in accordance with Section I of Rule 2.

11. ARRANGEMENTS FOR
VISUALDISPLAY
METERING:

If the customer wishes to have visual-display metering equipment in addition to the
regular metering equipment, and the customer would like PG&E to install that
equipment, the customer must submit a written request to PG&E. PG&E will provide
and install the equipment within 180 days of receiving the request. The visual-display
metering equipment will be installed near the present metering equipment. The
customer will be responsible for providing the required space and associated wiring.
PG&E will continue to use the regular metering equipment for billing purposes.

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(Continued)
Advice Letter No:
Decision No.
10D9

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

Sheet 11

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE
12.

BILLING:

35073-E
34702-E

A customer’s bill is calculated based on the option applicable to the customer.
Bundled Service Customers receive supply and delivery services solely from PG&E. The
customer’s bill is based on the Total Rates and Conditions set forth in this schedule.
Transitional Bundled Service Customers take transitional bundled service as prescribed
in Rules 22.1 and 23.1, or take bundled service prior to the end of the six (6) month advance
notice period required to elect bundled portfolio service as prescribed in Rules 22.1 and
23.1. These customers shall pay charges for transmission, transmission rate adjustments,
reliability services, distribution, nuclear decommissioning, public purpose programs, New
System Generation Charges1, the applicable Cost Responsibility Surcharge (CRS) pursuant
to Schedule DA CRS or Schedule CCA CRS, and short-term commodity prices as set forth
in Schedule TBCC.
Direct Access (DA) and Community Choice Aggregation (CCA) Customers purchase
energy from their non-utility provider and continue receiving delivery services from PG&E.
Bills are equal to the sum of charges for transmission, transmission rate adjustments,
reliability services, distribution, public purpose programs, nuclear decommissioning, New
System Generation Charges1, the franchise fee surcharge, and the applicable CRS. The
CRS is equal to the sum of the individual charges set forth below. Exemptions to the CRS
are set forth in Schedules DA CRS and CCA CRS.

Facilities which meet the eligibility criteria in Rule 19.2 or 19.3 are eligible for a California
Alternate Rates for Energy discount under Schedule E-CARE. CARE customers are
exempt from paying the DWR Bond Charge. For CARE customers, no portion of the
rates shall be used to pay the DWR Bond Charge. Generation is calculated residually
based on the total rate less the sum of the following: Transmission, Transmission Rate
Adjustments, Reliability Services, Distribution, Public Purpose Programs, Nuclear
Decommissioning, Competition Transition Charge (CTC), and Energy Cost Recovery
Amount.

14. ELECTRIC
EMERGENCY
PLAN
ROTATING
BLOCK
OUTAGES:

As set forth in CPUC Decision 01-04-006, all transmission level customers except
essential use customers, Optional Binding Mandatory Curtailment (OBMC) plan
participants, net suppliers to the electrical grid, or others exempt by the Commission, are
to be included in rotating outages in the event of an emergency. A transmission level
customer who refuses or fails to drop load shall be added to the next rotating outage
group so that the customer does not escape curtailment. If the transmission level
customer fails to cooperate and drop load at PG&E’s request, automatic equipment
controlled by PG&E will be installed at the customer’s expense per Electric Rule 2. A
transmission level customer who refuses to drop load before installation of the
equipment shall be subject to a penalty of $6/kWh for all load requested to be curtailed
that is not curtailed. The $6/kWh penalty shall not apply if the customer’s generation
suffers a verified, forced outage and during times of scheduled maintenance. The
scheduled maintenance must be approved by both the ISO and PG&E, but approval
may not be unreasonably withheld.

15. STANDBY
APPLICABILITY:

SOLAR GENERATION FACILITIES EXEMPTION: Customers who utilize solar
generating facilities which are less than or equal to one megawatt to serve load and who
do not sell power or make more than incidental export of power into PG&E’s power grid
and who have not elected service under Schedule NEM, will be exempt from paying the
otherwise applicable standby reservation charges.
DISTRIBUTED ENERGY RESOURCES EXEMPTION: Any customer under a
time-of-use (TOU) rate schedule using electric generation technology that meets the
criteria as defined in Electric Rule 1 for Distributed Energy Resources is exempt from the
otherwise applicable standby reservation charges. Customers qualifying for this
exemption shall be subject to the following requirements. Customers qualifying for an
exemption from standby charges under Public Utilities (PU) Code Sections 353.1 and
353.3, as described above, must take service on a TOU schedule in order to receive this
exemption until a real-time pricing program, as described in PU Code 353.3, is made
available. Once available, customers qualifying for the standby charge exemption must
participate in the real-time program referred to above. Qualification for and receipt of
this distributed energy resources exemption does not exempt the customer from
metering charges applicable to TOU and real-time pricing, or exempt the customer from
reasonable interconnection charges, non-bypassable charges as required in Preliminary
Statement BB - Competition Transition Charge Responsibility for All Customers and
CTC Procurement, or obligations determined by the Commission to result from
participation in the purchase of power through the California Department of Water
Resources, as provided in PU Code Section 353.7.

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(Continued)
Advice Letter No:
Decision No.
12D9

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Revised

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE

35075-E
31285-E

Sheet 13

16. DWR BOND
CHARGE:

The Department of Water Resources (DWR) Bond Charge was imposed by California
Public Utilities Commission Decision 02-10-063, as modified by Decision 02-12-082, and is
property of DWR for all purposes under California law. The Bond Charge applies to all
retail sales, excluding CARE and Medical Baseline sales. The DWR Bond Charge (where
applicable) is included in customers’ total billed amounts.

17. PEAK DAY
PRICING
DETAILS:

a.

Default Provision: The default of eligible customers to PDP will occur once per year
with the start of their billing cycle on or after November 1. Eligible customers will have
at least 45-days notice prior to their planned default date when they may opt-out of
PDP rates to take service on TOU rates. During the 45-day period, customers will
continue to take service on their non-PDP rate. Customers will be defaulted to PDP
unless they opt-out to a TOU rate at least five (5) days prior to their planned default
date. Existing customers on a PDP rate eligible demand response program will have
the option to enroll.

b.

Capacity Reservation Level: Customers may elect a capacity reservation level (CRL)
and pay for a fixed level of capacity, specified in kW. While the CRL is applicable
year round, customers electing a CRL will be billed under a take-or-pay basis up to
the specified CRL under the non-PDP rate of this schedule during the summer period
(May 1 through October 31). This means that customers will be billed for summer
peak generation demand charges up to the level of their CRL, even in summer
months when the actual demand might be less than their CRL. Customers will
receive PDP credits on summer usage above the CRL on summer period non-PDP
days. All usage during a PDP event protected under the CRL will be billed at the nonPDP rate. All usage above the CRL (as measured in 15-minute intervals), and not
protected during a PDP event, will be billed at the PDP rate.
If a customer fails to elect an initial CRL, the customer’s initial CRL will be set at 50%
of its most recent six (6) summer months’ average peak-period maximum demand
and may go back to the previous year to make a full summer season (if available). If
the customer has not established any historic summer billing demand, the CRL will be
set at zero (0).
A customer may only elect to change their CRL once every 12 months.

c.

Bill Stabilization: PDP customers will be offered bill stabilization for the initial twelve
(12) months unless they opt-out during their initial 45-day period. Bill stabilization
ensures that during the initial 12 months under PDP, the customer will not pay more
than it would have had it opted-out to the applicable TOU rate.
If a customer terminates its participation on the PDP rate prior to the initial 12 month
period expiring, the customer will receive bill stabilization up to the date when the
customer terminates its participation. Bill stabilization benefits will be computed on a
cumulative basis, based on the earlier of 1) when a customer terminates its
participation on the PDP rate or 2) at the end of the initial 12-month period. Any
applicable credits will be applied to the customer’s account on a subsequent regular
bill. Bill stabilization is only available one time per customer. If a customer un-enrolls
or terminates its participation on a PDP rate, bill stabilization will not be offered again.

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(Continued)
Advice Letter No:
Decision No.
13D9

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Original

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE

17. PEAK DAY
PRICING
DETAILS
(continued):

d.

35076-E
29102-E

Sheet 14

Notification Equipment: Customers, at their expense, must have access to the
Internet and an e-mail address or a phone number to receive notification of a PDP
event. In addition, all customers can have, at their expense, an alphanumeric pager
or cellular telephone that is capable of receiving a text message sent via the
Internet, and/or a facsimile machine to receive notification messages.
If a PDP event occurs, customers will be notified using one or more of the abovementioned systems. Receipt of such notice is the responsibility of the participating
customer. PG&E will make reasonable efforts to notify customers; however it is the
customer’s responsibility to maintain accurate notification contact information,
receive such notice and to check the PG&E website to see if an event is activated.
PG&E does not guarantee the reliability of the phone, text messaging, e-mail
system or Internet site by which the customer receives notification.
PG&E may conduct notification test events once a month to ensure a customer’s
contact information is up to date. These are not actual PDP events and no load
reduction is required.

e.

Demand Response Operations Website: Customers can use PG&E’s demand
response operations website located at https://inter-act.pge.com for load curtailment
event notifications and communications.
The customer’s actual energy usage is available at PG&E’s demand response
operations website. This data may not match billing quality data, and the customer
understands and agrees that the data posted to PG&E’s demand response
operations website may be different from the actual bill.

f.

Program Operations: A maximum of fifteen (15) PDP events and a minimum of
nine (9) PDP events may be called in any calendar year. PG&E will notify
customers by 2:00 p.m. on a day-ahead basis when a PDP event will occur the next
day. The PDP program will operate year-round and PDP events may be called for
any day of the week. PDP events will be called from 2:00 p.m. to 6:00 p.m.

g.

Event Cancellation: PG&E may initiate the cancellation of a PDP event before 4:00
p.m. the day-ahead of a noticed PDP event. If PG&E cancels an event, it will count
the cancelled event toward the PDP limits.

h.

Event Trigger: PG&E will trigger a PDP event when the day-ahead temperature
forecast trigger is reached. The trigger will be the average of the day-ahead
maximum temperature forecasts for San Jose, Concord, Red Bluff, Sacramento and
Fresno.
Beginning May 1 of each summer season, the PDP events on non-holiday
weekdays will be triggered at 98 degrees Fahrenheit (°F), and will be triggered at
105°F on holidays and weekends. If needed, PG&E will adjust the non-holiday
weekday trigger up or down over the course of the summer to achieve the range of
9 to 15 PDP events in any calendar year. Such adjustments would be made no
more than once per month and would be posted to the demand response
operations website.

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(Continued)
Advice Letter No:
Decision No.
14D9

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

February 2, 2015

Pacific Gas and Electric Company
San Francisco, California
U 39

Cancelling

Revised
Original

Cal. P.U.C. Sheet No.
Cal. P.U.C. Sheet No.

ELECTRIC SCHEDULE E-20
SERVICE TO CUSTOMERS WITH MAXIMUM
DEMANDS of 1000 KILOWATTS or MORE

Sheet 15

PDP events may also be initiated as warranted on a day-ahead basis by 1) extreme
system conditions such as special alerts issued by the California Independent
System Operator, 2) under conditions of high forecasted California spot market
power prices, 3) to meet annual PDP event limits for a calendar year, or 4) for
testing/evaluation purposes.

17. PEAK DAY
PRICING
DETAILS
(continued):
i.

Program Terms: A customer may opt-out anytime during their initial 12 months on
a PDP rate. After the initial 12 months, customer’s participation will be in
accordance with Electric Rule 12.
Customers may opt-out of a PDP rate at anytime to enroll in another demand
response program beginning May 1, 2011.

j.

18. Option R

Interaction with Other PG&E Demand Response Programs: Customers on a PDP
rate may participate in a day-of dispatchable demand response program as
established in D.09-08-027.

The Option R rate is available to qualifying E-20 customers with PV systems that provide
15% or more of their annual electricity usage.
For a customer installing a new PV system, this eligibility requirement will be calculated
as follows:
Annual PV system output1/Annual electricity usage2 ≥ 15%
For a customer with an existing PV system, this eligibility requirement will be calculated
as follows:
3
3
2
Annual PV system output /(Annual PV system output +Annual electricity usage ) ≥ 15%

_________________________
For a customer installing a new system, annual PV system output (kWh) will be
estimated as CEC rating of the panels (kW)* 8,760 hours/year * 18% capacity factor.
2
Annual electricity usage (kWh) will be measured at the PG&E meter over the last 12
months.
3
For a customer with an existing system, the customer may choose to supply PG&E
with reliable metered data measuring annual PV system output, if such data are
available. Alternatively, annual PV system output will be estimated using the formula
in footnote 1.
1

Advice Letter No:
Decision No.
15D12

4581-E
14-12-080

Issued by
Steven Malnight
Senior Vice President
Regulatory Affairs

Date Filed
Effective
Resolution No.

35077-E
29103-E

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